Wellbore plug

ABSTRACT

A wellbore plug comprises a body received within a tubular in an oil or gas well, and engaging a seat to seal an annulus. A sealing member occludes the bore in a first configuration. A spring urges the sealing member towards one end of the body in the first configuration. A locking member locks the sealing member in the first configuration, and can be unlocked in response to pressure within the bore above a pressure threshold, which permits movement of the sealing member to a second configuration. The spring expands when pressure within the bore is reduced below the threshold to push the sealing member into a third configuration, which permits fluid passage through the bore. A method of pressure testing and a method of injecting fluid into a well is also disclosed, using the wellbore plug.

The present application relates to a wellbore plug for use in an oil orgas well, in order to control the flow of fluid through the wellbore.Wellbore plugs are conventionally used in wellbore tubulars such asproduction tubing, frequently when a tubing string pressure test is tobe performed, after the tubing string has been assembled in the well,usually after cementing has been completed, and typically beforeproduction of hydrocarbons through e.g. the production string. Pressuretesting at this stage often identifies leaks in the production stringwhich can therefore be addressed before production starts. Suitablepressure tests are therefore good practice, especially before highpressure wellbore operations such as fracking, and are often mandated bydrilling regulations in most territories.

During conventional pressure testing, a wellbore tubing plug is normallydropped from the surface into a production string, usually duringcementing operations, and is usually landed in or near a section of thewell known as the toe or foot above the formation being produced,typically seating on a shoulder within the well, and occluding the boreof the tubing above it, permitting pressure testing above the seatedplug. After pressure testing, the plug can be drilled out, or in othercases, the plug can be formed from soluble material which dissolvesafter a predetermined time.

SUMMARY

According to the present invention there is provided a wellbore plugcomprising:

-   -   a body having an axis and a bore adapted to transmit fluid        between a first end of the body and a second end of the body,        the body being adapted to be received within a tubular in an oil        or gas well, and being adapted to engage a seat within the oil        or gas well tubular to seal an annulus between the outer surface        of the body and an inner surface of the tubular;    -   a sealing member adapted to occlude the bore through the body to        resist fluid flow through the bore of the body when the wellbore        plug is in a first configuration;    -   a resilient device adapted to urge the sealing member towards        one end of the body when the wellbore plug is in the first        configuration;    -   a locking member adapted to lock the sealing member in the first        configuration, and adapted to be unlocked in response to        pressure within the bore above a pressure threshold;    -   wherein unlocking of the locking member permits movement of the        sealing member within the bore to shift the wellbore plug from        the first configuration to a second configuration;    -   wherein movement of the sealing member in response to expansion        of the resilient device when pressure within the bore is reduced        below the threshold shifts the wellbore plug from the second        configuration to a third configuration; and    -   wherein in the third configuration, the sealing member permits        fluid passage through the bore between the first and second ends        of the body.

The invention also provides a method of pressure testing a well,comprising:

-   -   plugging a tubular in the well by seating a wellbore plug in the        tubular, the wellbore plug comprising a body having an axis and        a bore adapted to transmit fluid between a first end of the body        and a second end of the body, the wellbore plug having a sealing        member occluding the bore through the body to resist fluid flow        through the bore of the body when the wellbore plug is in a        first configuration, a resilient device adapted to urge the        sealing member towards one end of the body when the wellbore        plug is in the first configuration, and a locking member adapted        to lock the sealing member in the first configuration, and        adapted to be unlocked in response to pressure within the bore        above a pressure threshold;    -   applying a pressure differential across the locked sealing        member by pressurising the bore above the sealing member and        unlocking the locking member;    -   moving the unlocked sealing member within the bore to shift the        wellbore plug from the first configuration to a second        configuration;    -   reducing the pressure differential across the sealing member and        moving the sealing member within the bore in response to        expansion of the resilient device to shift the wellbore plug        from the second configuration to a third configuration; and    -   permitting fluid passage through the bore between the first and        second ends of the body when the wellbore plug is in the third        configuration.

Optionally the locking member is a frangible member such as one or morepins adapted to shear above a threshold shearing force, applied by thepressure acting on the sealing member in the bore. Instead of pins, thelocking member could be a ring or collet or split ring etc. Optionallythe sealing member is axially restrained within the bore by the lockingmember (e.g. one or more shear pins). Optionally, in the firstconfiguration, axial movement of the sealing member is resisted in bothdirections of the bore by the locking member when the locking member islocked. Optionally the sealing member is able to move from the firstconfiguration in both axial directions within the bore after the lockingmember is unlocked. Optionally a seal is compressed between the outersurface of the sealing member and the inner surface of the bore in thefirst and second configurations, to occlude the bore and to resist orprevent fluid flow in the bore past the sealing member in the first andsecond configurations. Optionally the sealing member moves in onedirection when the wellbore plug shifts from the first to the secondconfiguration, and in the opposite direction when the wellbore plugshifts from the second configuration to the third configuration.

Optionally the wellbore plug comprises a dart with a hydrodynamicprofile adapted to flow through a fluid column in the well in a singledirection (i.e. down the string).

In some examples, the arrangement of features permits pressure testingwhile avoiding or minimising trips through the well before operationscommence after the test. Some examples permit re-establishment of fluidcirculation through the well after pressure testing concludes, simply byreducing the pressure differential above the seated wellbore plug. Someexamples avoid the need for separate frangible valve members, such asrupture discs.

Optionally the bore has a catching chamber having a larger innerdiameter than the sealing member, optionally disposed above the locationof the sealing member in the first configuration, providing a clearancepermitting fluid flow between the inner surface of the bore of the firstportion and the outer surface of the sealing member. Hence the sealingmember optionally does not seal the bore in the catching chamber.Optionally the catching chamber retains the sealing member in the thirdconfiguration, and permits fluid flow around the sealing member withinthe catching chamber.

Optionally the bore has a seal housing having an inner diameter in whichthe sealing member is received in a sliding fit. The seal housingoptionally has a smaller diameter than the catching chamber. Optionallya first shoulder restricts axial movement of the sealing member withinthe seal housing. Optionally the shoulder is disposed in the sealhousing. Optionally the sealing member has a shoulder facing in a firstdirection and the seal housing has a shoulder facing in the oppositedirection. Optionally the two shoulders engage to limit axial movementof the sealing member within the seal housing. Optionally the sealhousing is radially stepped, with a larger diameter portion and asmaller diameter portion and the first shoulder is disposed between thetwo portions. Optionally a seal is compressed between the inner surfaceof the seal housing and the outer surface of the sealing member.Optionally the seal is a resilient seal. Optionally the seal is anannular seal such as an O-ring, T-seal, P-seal or the like. Optionallythe seal is adapted to seal the bore in both directions when the seal iscompressed between the sealing member and the seal housing. Optionallythe seal is a dynamic seal, adapted to resist fluid passage while theseal is sliding relative to the one of the sealing member and the sealhousing. Optionally the seal is disposed on the sealing member, butcould be disposed on the seal housing, e.g. in a groove on eithercomponent.

Optionally the sealing member resists or prevents fluid flow in thefirst and second configurations; for example, the seal can be compressedbetween the outer surface of the sealing member and the inner surface ofthe seal housing in both the first and the second configurations.Optionally a first force urging the sealing member in one direction as aresult of fluid pressure in the bore at the fluid pressure threshold ishigher than a second force urging the sealing member in the oppositedirection as a result of the resilient device. Optionally the wellboreplug remains in the second configuration when the first force is greaterthan the second force. When the fluid pressure declines and the firstforce drops below the second force, the resilient member optionallyurges the sealing member from the second configuration into the thirdconfiguration (optionally in the opposite direction). Thus, the sealingmember is fixed in the first configuration by the locking device, whichmust be unlocked before the wellbore plug can shift from the firstconfiguration to the second configuration, but after unlocking, thesealing member is held in the second configuration by a force imbalancebetween the first force and second force, and is free to move axiallyafter within the bore during the shift from second to thirdconfiguration after the force imbalance is removed.

After unlocking, the sealing member is optionally free to move axiallywhile still holding pressure, and is moved under pressure differentialin an axial direction within the bore as the wellbore plug shifts fromthe first to the second configuration.

Optionally the seal housing contains the resilient device. Optionallythe resilient device is adapted to be energised (e.g. compressed)between the sealing member and a shoulder in the seal housing.

Optionally the seal housing extends axially further than the axiallength of the sealing member, so that the sealing member is axiallyshorter than the second portion, and can slide axially within it whilesealing the bore in different axial positions within the seal housing.In the first configuration the sealing member is optionally locked inthe seal housing, and in the first configuration, a stop member of thesealing member (e.g. a shoulder) is optionally axially spaced from thefirst shoulder on the seal housing.

Optionally in the second configuration the movement of the sealingmember relative to the seal housing is arrested by the first shoulder.For example, the stop member on the sealing member abuts the firstshoulder on the seal housing. Optionally the movement of the sealingmember as the wellbore plug shifts from the first to the secondconfiguration from compresses the resilient device. Optionally theresilient device comprises a spring. Optionally the resilient device isheld in compression in the first and second configurations. Optionallythe resilient device stores energy (e.g. a spring is compressed further)when the wellbore plug shifts from the first to the secondconfiguration. Optionally the resilient device releases energy when thewellbore plug shifts from the second configuration to the thirdconfiguration.

Optionally the sealing member and the body are separate. Optionally thebody and the sealing member are run into the well separately. Optionallythe sealing member can latch onto the body and can optionally form aseal with the body e.g. by compressing resilient seals between thesealing member and the body. Optionally the sealing member has wipervanes. Optionally the body has wiper vanes. Optionally the vanes on thesealing member have a different (e.g. smaller) diameter than the vaneson the body; optionally the body and sealing member wipe different partsof the tubular. Optionally the body is pinned in place and run into thewell with the tubular (e.g. string). Optionally the sealing member isrun into the tubular, and lands in the body that is pinned in place.

Optionally the tubular includes a landing sub having a bore (optionallywith a seat) adapted to receive the plug following axial movement of theplug in the string. Optionally the seat comprises at least onecylindrical portion, and optionally at least one tapered portion.Optionally the plug comprises at least one cylindrical portion andoptionally at least one tapered portion. Optionally when the plug isseated in the landing sub, the axial distance of penetration through thebore of the landing sub is limited by the abutment of the taperedportions of the landing sub and the plug.

Optionally the landing sub contains at least one port permitting fluidcommunication between the bore of the landing sub and the outer surfaceof the string. Optionally the port is adapted to be closed by a sleevethat slides axially within the bore, optionally in response to apressure differential or to a flow rate minimum. Optionally the body ofthe plug is adapted to urge the movement of the sleeve when the pluglands in the landing sub. Optionally the sleeve is secured to thelanding sub by a latch e.g. by a frangible member such as a shear pin,although other latch devices could be used, e.g. collets, split ringsetc. Optionally the latch is released by the movement of the plugthrough the landing sub, optionally by force applied to the plug byfluid pressure above the seated plug being transmitted to the sleevethrough the body of the plug, optionally while the bore is sealed.

Optionally the plug can move axially with respect to the landing subwhile the bore is sealed through the landing sub and the plug.Optionally the cylindrical sections of the landing sub and plug permitaxial movement of the two while sealing is maintained.

Optionally the port is below the axial position in the landing sub wherethe plug seats in the landing sub.

Optionally the method of the invention includes injecting fluid into thewell through the plug e.g. to fracture or otherwise treat the formation.

Optionally the plug can be latched or locked to the tubular (e.g. in alanding sub) by a latch device. Optionally the latch device resistsmovement of the plug in one direction but not in the other direction.Optionally, the latch device permits movement of the plug into the well,but resists movement towards the surface. Optionally the latch deviceretains the plug and the tubular in a sealed relationship.

Optionally the sealing member incorporates a channel permittingselective fluid communication across the sealing member when seated inthe body, and wherein the channel incorporates a seal preventing fluidcommunication through the channel below a pressure differential above aburst pressure, and wherein the seal is adapted to be disrupted by apressure differential above the burst pressure to permit fluidcommunication through the channel.

The invention also provides a method of injecting fluid into a well,comprising: plugging a tubular in the well by seating a wellbore plug inthe tubular, the wellbore plug comprising a body having an axis and abore adapted to transmit fluid between a first end of the body and asecond end of the body, the wellbore plug having a sealing memberoccluding the bore through the body to resist fluid flow through thebore of the body when the wellbore plug is in a first configuration, aresilient device adapted to urge the sealing member towards one end ofthe body when the wellbore plug is in the first configuration, and alocking member adapted to lock the sealing member in the firstconfiguration, and adapted to be unlocked in response to pressure withinthe bore above a pressure threshold;

-   -   applying a pressure differential across the locked sealing        member by pressurising the bore above the sealing member and        unlocking the locking member;    -   moving the unlocked sealing member within the bore to shift the        wellbore plug from the first configuration to a second        configuration;    -   reducing the pressure differential across the sealing member and        moving the sealing member within the bore in response to        expansion of the resilient device to shift the wellbore plug        from the second configuration to a third configuration;    -   injecting fluid through the bore between the first and second        ends of the body when the wellbore plug is in the third        configuration; and    -   flowing the injected fluid through a radial port in the tubular        located below the seated plug.

The various aspects of the present invention can be practiced alone orin combination with one or more of the other aspects, as will beappreciated by those skilled in the relevant arts. The various aspectsof the invention can optionally be provided in combination with one ormore of the optional features of the other aspects of the invention.Also, optional features described in relation to one aspect cantypically be combined alone or together with other features in differentaspects of the invention. Any subject matter described in thisspecification can be combined with any other subject matter in thespecification to form a novel combination.

Optionally the wellbore plug can incorporate a centraliser device, suchas a cup or an array of fins.

Optionally the bore can incorporate a seat or latch device permittingthe connection and optionally sealing of a second wellbore plug,optionally at an upper end of the bore. Thus in one example, theinvention provides a wellbore plugging system comprising two or morewellbore plugs as herein defined, connected in sequence.

Various aspects of the invention will now be described in detail withreference to the accompanying figures. Still other aspects, features,and advantages of the present invention are readily apparent from theentire description thereof, including the figures, which illustrates anumber of exemplary aspects and implementations. The invention is alsocapable of other and different examples and aspects, and its severaldetails can be modified in various respects, all without departing fromthe spirit and scope of the present invention. Accordingly, each exampleherein should be understood to have broad application, and is meant toillustrate one possible way of carrying out the invention, withoutintending to suggest that the scope of this disclosure, including theclaims, is limited to that example. Furthermore, the terminology andphraseology used herein is solely used for descriptive purposes andshould not be construed as limiting in scope. In particular, unlessotherwise stated, dimensions and numerical values included herein arepresented as examples illustrating one possible aspect of the claimedsubject matter, without limiting the disclosure to the particulardimensions or values recited. All numerical values in this disclosureare understood as being modified by “about”. All singular forms ofelements, or any other components described herein are understood toinclude plural forms thereof and vice versa.

Language such as “including”, “comprising”, “having”, “containing”, or“involving” and variations thereof, is intended to be broad andencompass the subject matter listed thereafter, equivalents, andadditional subject matter not recited, and is not intended to excludeother additives, components, integers or steps. Likewise, the term“comprising” is considered synonymous with the terms “including” or“containing” for applicable legal purposes. Thus, throughout thespecification and claims unless the context requires otherwise, the word“comprise” or variations thereof such as “comprises” or “comprising”will be understood to imply the inclusion of a stated integer or groupof integers but not the exclusion of any other integer or group ofintegers.

Any discussion of documents, acts, materials, devices, articles and thelike is included in the specification solely for the purpose ofproviding a context for the present invention. It is not suggested orrepresented that any or all of these matters formed part of the priorart base or were common general knowledge in the field relevant to thepresent invention.

In this disclosure, whenever a composition, an element or a group ofelements is preceded with the transitional phrase “comprising”, it isunderstood that we also contemplate the same composition, element orgroup of elements with transitional phrases “consisting essentially of”,“consisting”, “selected from the group of consisting of”, “including”,or “is” preceding the recitation of the composition, element or group ofelements and vice versa. In this disclosure, the words “typically” or“optionally” are to be understood as being intended to indicate optionalor non-essential features of the invention which are present in certainexamples but which can be omitted in others without departing from thescope of the invention.

References to directional and positional descriptions such as upper andlower and directions e.g. “up”, “down” etc. are to be interpreted by askilled reader in the context of the examples described to refer to theorientation of features shown in the drawings, and are not to beinterpreted as limiting the invention to the literal interpretation ofthe term, but instead should be as understood by the skilled addressee.In particular, positional references in relation to the well such as“up” and similar terms will be interpreted to refer to a directiontoward the point of entry of the borehole into the ground or the seabed,and “down” and similar terms will be interpreted to refer to a directionaway from the point of entry, whether the well being referred to is aconventional vertical well or a deviated well.

BRIEF DESCRIPTION OF THE DRAWINGS

In the accompanying drawings:

FIG. 1 shows a side view of a plug device according to an example of theinvention;

FIG. 2 shows a sectional view through line A-A of the FIG. 1 plug devicein a first configuration;

FIG. 3 shows a sectional view of the FIG. 1 plug device in a secondconfiguration;

FIG. 4 shows a sectional view of the FIG. 1 plug device in a thirdconfiguration;

FIG. 5 shows a side view of a second example of a plug device beforewiping a payzone;

FIG. 6 shows a section view of the FIG. 5 arrangement after landing in asub following the wiping of the payzone;

FIGS. 7 to 10 show views of a third example of a wellbore plug landingin a shoe landing sub above a float shoe showing sequential steps oflanding (FIG. 8), pressure testing (FIG. 9), and permittingcommunication between the bore of the well and side ports in the landingsub following the pressure test (FIG. 10);

FIG. 11 shows a perspective view of a landing sub for the FIG. 7wellbore plug; and

FIG. 12 shows a detailed view of one optional modification to the FIGS.7-11 plug.

Referring now to the drawings, FIGS. 1 to 4 show side and sectionalviews through a typical example of a wellbore plug according to theinvention. The wellbore plug has a body 10 comprising generallycylindrical sections which can optionally be screwed together, orotherwise attached. In this example, the wellbore plug comprises anupper section comprising a seal catcher 20, a middle section comprisinga seal housing 50, and a lower section comprising a nose 80. Thecomponents are provided with a common central bore 10 b extending fromone end of the body 10 to the other. More or less than three sectionscan be provided in other examples. In one particular example, the nose80 and seal housing 50 can optionally be integral. The outer surface ofthe body 10 is generally consistent between the seal catcher 20 and theseal housing 50, but the nose 80 generally has a smaller OD withoptional drogue fins 82 extending radially from its outer surface in agenerally conical arrangement, and expanding radially outward in anangle towards the upper end of the wellbore plug 1 beyond the OD of theupper sections 20, 50. In this example, the upper end of the wellboreplug 1 is shown at the left-hand side of the drawings, and the lower endis shown at the right hand side of the drawings. In operation, thewellbore plug 1 is launched into a tubing string forming part of thewellbore with the nose 80 offered into the bore of the tubing first(e.g. nose down), and with the fins 82 extending radially outward,optionally contacting the inner surface of the tubular being plugged.The fins 82 are optionally formed from a resilient polymeric material,and so optionally deform radially inward when compressed against theinner surface of the wellbore tubular in which the wellbore plug 1 isbeing deployed, although this is not necessary in all examples, and thewellbore plug 1 can be used in tubing strings that have a larger ID thanthe OD of the fins 82, as the function of the fins 82 is mainly to helpthe wellbore plug 1 to flow with the fluid through the tubing. Thewellbore plug 1 is pumped towards a seat (not shown) in the tubing atwhich a lower sealing arrangement 85 which in this example comprises apair of annular seals such as o-rings on the outer surface of the lowerpart of the nose 80 seats within a suitable seat on the inner surface ofthe tubing, thereby plugging the annulus between the wellbore plug 1 andthe tubing and resisting further fluid passage past the seated wellboreplug 1. Optionally the nose 80 has a retaining device (in this examplecomprising a ratchet mechanism 90) which retains the nose 80 on the seatonce seated.

As can be seen in the sectional view of FIG. 2, an upper end of the nose80 has a retaining mechanism which can be a thread adapted to engagewith a thread on the lower end of the seal housing 50 but which in thisexample comprises a ratchet mechanism 52 similar to ratchet mechanism90, and the upper end of the seal housing 50 likewise has a male threadadapted to be engaged by a female thread on the inner surface of thelower end of the upper portion 20. The components 20, 50 80 can beconnected in different ways. Suitable seals can be incorporated to sealthe body components 20, 50, 80 together.

FIG. 2 shows the internal details of the wellbore plug 1 in the firstconfiguration, which is the default configuration when running into thehole to land at the desired depth on the seat, whereas FIGS. 3 and 4show second and third configurations of the plug during and after apressure test operation respectively, which will be explained below.

Referring now to FIG. 2, the seal housing 50 has a radially steppedinternal bore with a narrow diameter lower section stabbed into theupper end of the nose 80 so as to permit fluid communication between thebore of the seal housing 50 and the bore of the nose 80, and a widerdiameter section above it, with an upwardly facing shoulder 55 whichextends radially into the bore between the two sections of the sealhousing 50. In this example, the resilient device takes the form of acoiled spring 70, which is housed within a spring cavity 57 within thewider diameter bore above the shoulder 55. FIG. 2 shows the firstconfiguration with the spring 70 in compression between the shoulder 55and the lower surface of a sealing member which in this example takesthe form of a piston 60, the lower end of which is a sliding fit in thespring cavity 57. The piston 60 has a top hat structure, with an upperflange 62 extending radially outwards from a body that is generallycylindrical. The lower body has a close tolerance between the outerdiameter of the piston 60 and the inner diameter of the spring cavity57. At least one seal which in this example takes the form of an annularT-shaped seal 61 extends around the outer surface of the lower body ofthe piston 60, and in this example is housed in a groove therein, suchthat the seal 61 is held in compression between the outer surface of thelower body of the piston 60 and the inner surface of the seal housing50, thereby preventing fluid flow within the bore 10 b past the sealedlower body of the piston 60.

Above the spring cavity 57, the seal housing 50 is counter-bored to awider diameter in a locking cavity 59 in which the flange 62 of thepiston 60 is a sliding fit. The locking cavity therefore has a largerouter diameter than the spring cavity 57. A radially inwardly extendingshoulder 58 divides the locking cavity 59 from the spring cavity 57.

In this example, the flange 62 of the piston 60 extending radiallyoutward from the upper end of the lower body of the piston 60 is axiallyshorter than the axial distance of the locking cavity 59, measured fromthe end of the locking cavity to the shoulder 58. Hence, the piston 60can slide axially within the bore of the seal housing 50 for a distancebefore hitting the shoulder 58, while the body of the piston 60 isdisposed within the spring cavity 57, causing the lower body of thepiston 60 to extend further into the spring cavity 57 from the FIG. 1position as the piston 60 slides down the bore 10 b.

The piston 60 in this example is adapted to be locked to the sealhousing 50. In this example, the flange 62 has radial bores to receivethe inner ends of shear pins 65, which extend radially through acircumferential array of pin holes arranged at the same radial positionon the counter-bored upper end of the seal housing 50, optionally inthis case, above the screw thread and seal between the seal catcher 20and the seal housing 50. Optionally 12 pins are provided, but at leastone is sufficient. The pins 65 connect the flange 62 to the seal housing50 at or near to the upper end of the counter-bored locking cavity 59,so that the lower end of the flange 62 is spaced axially away from theshoulder as best seen in FIG. 2, and in fact, the upper end of theflange 62 extends slightly proud of the upper end of the locking cavity59 as best seen in FIG. 2. The pins 65 lock the piston 60 to the sealhousing 50 and hold the spring 70 in compression between the end of thelower body of the piston 60 and the shoulder 55 at the bottom of thespring cavity 57.

The seal catcher 20 has a large diameter seal catching chamber 21 abovethe piston 60, which has a larger diameter than the OD of the piston 60,so that fluid can flow past the piston 60 in the chamber 21, even pastthe flange 62, when the piston 60 is located in the seal catchingchamber 21. The seal catcher 20 is optionally connected to the sealhousing 50 by means of a threaded connection and optionally a seal (notshown).

In operation, the wellbore plug 1 is launched into the bore of thetubing in the FIG. 2 configuration, nose down, so that the lower end ofthe nose 80 engages the seat in the tubing (not shown), and so that inthis example, the retaining mechanism 90 engages to lock the wellboreplug 1 in that axial position. The bore 10 b in the nose 80 is open tothe bore below the seat through the outlet of the nose, but the annulusoutside the nose 80 is sealed by the seals 85 and fluid cannot passthrough the seat via the annulus. Thus, the only available fluid conduitfor communication past the seated nose 80 is through the bore 10 b.

In the FIG. 2 configuration (the first configuration) the pins 65 lockthe piston 60 axially within the seal housing 50, axially compressingthe spring 70 between the lower end of the piston 60 and the upwardlyfacing shoulder 55, and radially compressing the annular seal 61 betweenthe radially outermost surface of the piston 60 and the radiallyinnermost surface of the spring cavity 57, thereby preventing thepassage of fluid through the bore 10 b while the piston is in the firstconfiguration shown in FIG. 2. In this same first configuration, thelower end of the flange 62 on the piston 60 is axially spaced from theupwardly facing shoulder 58 on the seal housing 50. The pins 65 preventaxial movement of the piston 60 relative to the seal housing 50 atpressures below the unlocking threshold (to be explained below).

When the wellbore plug 1 is seated within the bore, and fluid flow pastthe outer surface of the wellbore plugging 1 is prevented by theinteraction between the seal 85 and the seat, the locked piston 60 andseal 61 prevents the passage of fluid through the bore 10 b, therebyclosing off the bore 10 b when the wellbore plug 1 is seated.

At this stage, a pressure test can be conducted, to pressure up the bore10 b above the seated wellbore plug 1 and check for leaks in the tubingstring. In the pressure test, typically a pressure is maintained withinthe bore above the seated plug, and this high pressure is optionallyheld for a predetermined time period, in order to verify that thepressure can be held over time.

In this example, the locking member comprising the shear pins 65 isselected to unlock at a pressure threshold below the pressure testthreshold, so that once the pressure test threshold is reached toconduct the pressure test, the shear pins 65 have been ruptured, and thepiston 60 is no longer locked to the seal housing 50. The strength ofthe spring 70 in this example is selected to be relatively weak,typically weaker than the force exerted on the piston 60 at the pressurethreshold for disrupting the locking device, so when the shear pins 65rupture, and the piston 60 is unlocked from the FIG. 2 position, thepressure differential across the piston 60 pushes the piston 60 furtherinto the bore to the position shown in FIG. 3 thereby compressing thespring 70 further within the spring cavity 57 until the lower surface ofthe flange 62 hits the upper surface of the shoulder 58 on the sealhousing 50 which arrests the axial travel of the piston 60. At thisstage, the wellbore plug 1 is in the configuration shown in FIG. 3,which is the second configuration. In this configuration (in thisexample) the piston 60 is unlocked since the pins 65 have sheared, butthe piston 60 is still held in the second configuration as long as thepressure differential across the piston urging the piston 60 downwardsis sufficiently high to overcome the force of the spring 70 held incompression between the piston 60 and the shoulder 55. In this example,the strength of the spring 70 can be selected to be relatively weak, andoptionally the shear pins can be adapted to rupture at a relatively lowpressure, which can for example be some way below the pressure testvalue. This provides the operator with some assurance that once thepressure within the bore 10 b above the piston 60 passes the relativelylow unlocking threshold, the shear pins 65 will be ruptured, and thepiston 60 will be in the second configuration shown in FIG. 3. Inpractice, the unlocking threshold can be set at any desired pressure, byvarying the strength of the resilient device and the locking device.

In the second configuration as shown in FIG. 3, the seals 61 are stillradially compressed between the outer surface of the lower body of thepiston 60 and the inner surface of the spring cavity 57, so despite thefact that the shear pins 65 have ruptured, and the piston 60 has moveddown the bore 10 b, the sealing member still seals the bore, preventingfluid passage through the bore between the two ends of the wellbore plug1 as long as the pressure is high enough to overcome the force of theresilient device in the form of the spring 70.

The second configuration shown in FIG. 3 can be held as long as thepressure test endures, since the relatively high pressure in the bore 10b above the sealed piston 60 is sufficient to compress the relativelyweak spring 70 in this case. After the pressure test has been concluded,the pressure can be released within the bore 10 b, until the pressuredifferential applied to the unlocked piston 60 is no longer sufficientto compress the spring 70, at which point, the spring 70 expands,pushing the piston 60 upwards out of the spring cavity 57 (i.e. in theopposite direction to the movement of the piston 60 from the firstconfiguration to the second configuration) and into the larger diameterseal catching cavity 21 within the seal catcher 20. This configurationis the third configuration, and is shown in FIG. 4. As shown in FIG. 4,the inner diameter of the seal catching cavity 21 within the sealcatcher 20 is larger (optionally very much larger) than the maximumouter diameter of even the flange 62 on the piston 60, and once in thethird configuration, the piston 60 does not substantially restrict fluidflow. Optionally the area of the cavity 21 when the sealing member inthe form of the piston 60 is within the seal catching cavity 21 is noless (i.e. at least the same as or greater than) the area of the bore 10b at its narrowest. Fluid is therefore free to flow through the bore 10b past the piston 60 in the seal catching cavity 21, through the springcavity 57, through the narrow bore at the lower end of the seal housing50, and into the nose 80, to the outlet thereof thereby re-establishingfluid communication through the bore after the pressure test.

Optionally a head 11 at the upper end of the body 10 can incorporate asealing bore 11 b can incorporate a seat or latching profile permittingthe connection and/or sealing of a second wellbore plug (not shown)above the wellbore plug 1 in a stacked array, connected in sequence.Optionally therefore, the wellbore plug 1 can land out on top of otherplugs or darts or cementing equipment already pre-seated or “run” ahead,during for example, a “wet shoe” cementing operation.

In the above described example, during the pressure test, wellborepressure in the string above the seated wellbore plug 1 is incommunication with the bore 10 b through the open upper end of the head11. In one possible modified example, the head 11 and/or the sealcatcher 20 can optionally incorporate additional ports to facilitatecommunication of pressure from the string above the seated plug 1 intothe bore 10 b, for example, radial ports disposed above the seatedpiston 60 (and typically above the screw thread connecting the sealcatcher 20 with the seal housing 50) can optionally extend through theside walls of the seal catcher 20 or head 11 connecting the annulusoutside the wellbore plug 1 with the bore 10 b inside. This canfacilitate the application of the pressure differential across thepiston 60 in the first configuration, and can allow annularcommunication with the bore 10 b when the plug 1 is in the thirdconfiguration.

Referring now to FIGS. 5 and 6, a second example of a wellbore plug hassimilar components to the wellbore plug described in FIGS. 1 to 4, butwith reference numbers increased by 100. Components that are similarbetween the two examples will not all be described in detail forbrevity, but the skilled reader will understand that the second examplecan incorporate any one or more or all of the features and functions ofthe first example. Likewise, any one or more or all of the features ofthe second example can be incorporated within the first example.

The wellbore plug 101 of FIGS. 5 and 6 has a body 110, a middle sectioncomprising a seal housing 150 and a nose 180. A common central bore 110b extends from one end of the body to the other. In this example, thereis no seal capture 20 equivalent component, and the seal housing 150receives a piston 160 which is pinned by shear pins 165 to the seal body150, and is sealed thereto by an O-ring between the two components. Inthis example, the sealing member comprising the piston 160 is simplypushed out of the body 110 and remains in the tubular above the body.

The piston 160 optionally has a flange 162 which limits the axial travelof the piston 160 within the seal housing 150, and is biased by thespring 170 which is optionally held in compression between the innersurface of the piston 160 and a shoulder within the spring cavity 157,urging the piston upwards. In this example, the piston 160 optionallyhas a tapered bore 160 b, which has a narrower inner diameter than thecoiled spring 170, and which has a seat that is adapted to receive asurface release plug 168, which has a nose section that lands within thebore 160 b and seals therein as shown in FIG. 6, thereby closing thebore through the body 110 and denying fluid passage through the bore 110when the surface release plug is seated in the body 110.

As shown in FIG. 5, the surface release plug 168 has a number ofexternal vanes above the nose which are adapted to wipe the innersurface of a narrow diameter line running string above a running tool inwhich the body 110 of the wellbore plug of this example is pinned.

In this example, when a cement job is to be run, the string is assembledduring insertion typically including casing shoe and float valves at thelower end of the string, followed by a landing sub 140, followed by asection of payzone liner with a large internal diameter that is hungbelow a running tool 141 in which is pinned the body 110 of the wellboreplug. The body 110 is optionally pinned at a transition point betweenthe larger lower diameter of the liner, and the relatively smaller innerdiameter of the liner running string above the running tool (shown atthe left-hand side of FIG. 5). Once the string has been run into thehole cement is pumped through the string. The cement typically flowseasily through the wide bore 110 b in the plug 101, which remains pinnedat the transition between the narrow and wide inner diameters in theliner during the injection of cement. The pins or other locking meansholding the plug 101 in place in the running tool can optionally have arelatively low shear rating, since the cement can typically flow throughthe internal bore 110 b of the body 110, through the open internal bore160 b of the piston 160 which is in turn pinned within the seal housing150 in the bore.

The body 110 optionally has external vanes along the outside of thecentral section, which deform against the inner surface of the largediameter casing below the running tool 141, and are adapted to wipe thelarge diameter lining following the injection of the cement from thesurface.

Above the running tool, the inner diameter of the liner running stringis narrower than the payzone liner, and is too narrow to accept the body110 of the wellbore plug. Hence the body 110 is run into the holealready pinned in place within the running tool 141.

After injection of the cement through the liner running string, liner,body 110 and landing sub 140 through the casing shoes at the foot of thestring, the entire liner must then be wiped of cement before the cementdries. This is optionally achieved by chasing the cement into the holewith the surface release plug 168, which typically has smaller vanesthan those of the body, and is adapted to wipe cement from the smallerinner diameter of the liner running string between the surface and therunning tool 141. Once the surface release plug 168 reaches the body 110pinned in place within the running tool 141 at the transition betweenthe two diameters of liner, it typically seats and optionally seals inthe central bore 160 b of the piston 160. Optionally the surface releaseplug can latch onto the body, e.g. inside the bore 160 b. Continuedpressure above the surface release plug typically applies a pressuredifferential that is sufficient to shear the relatively weak pinsholding the body 110 within the running tool 141. These pins canoptionally be sheared at a relatively low force, since they only need tohold the body 110 within the running tool 141 and resist the flow ofcement until all the cement is below the body 110.

Once the surface released plug 168 lands within the piston bore 160 band the weak pins are sheared, the assembled plug as shown in FIG. 6comprising the surface release plug 168 and the body 110 is releasedfrom the running tool 141 and travels down the larger diameter liner,chasing the cement and wiping the larger inner diameter of the payzoneliner as it travels. When the assembled plug reaches the landing sub140, the nose 180 of the plug lands in a seat and seals in the shoelanding sub 140, thereby closing the bore as previously described forthe first example, and permitting a pressure test to be completed aspreviously described for the first example.

The force applied by the pressure test shears the pins 165 holding thepiston 160 within the seal housing 150, and the piston 160 is then freeto move downwards in the body 110 under the pressure differential, tocompress the coiled spring 170 within the spring cavity 157 until theflange 162 on the piston tops out on the seal housing 150, essentiallyas previously described for the first example. Since the spring 170typically has a larger diameter than the nose of the surface releaseplug 168, the spring only applies a force to the piston 160 and not tothe surface release plug 168. Once the pressure test is concluded, thepressure above the sealed piston 160 is bled off until the downwardforce applied by the pressure differential acting on the sealed piston160 is less than the upward force applied by the coiled spring 170 heldin compression below the piston 160, at which point the coiled spring170 expands and pushes the piston 160 out of the seal housing 150. Atthis point communication through the bore 110 b is re-established again,essentially as previously described. The ejected piston 160 is notretained in any kind of catching chamber, but instead simply remains inthe tubing above the seated body 110.

While not every aspect of the first example has been described withrespect to the second example, all of the features of the first examplecould be incorporated within the second example, and vice versa.

Referring now to FIGS. 7-10, a third example of a wellbore plug hassimilar components to the wellbore plugs described in FIGS. 1 to 4, butwith reference numbers increased by 200. Components that are similar inthis example to features described in the two earlier examples will notall be described in detail for brevity, but the skilled reader willunderstand that the third example can incorporate any one or more or allof the features and functions of the first or second examples. Likewise,any one or more or all of the features of the third example can beincorporated within the first or second examples.

The wellbore plug 201 of FIGS. 7-10 has a body 210, a middle sectioncomprising a seal housing 250 and a nose 280. A common central bore 210b extends from one end of the body to the other. In this example, thereis no seal capture 20 equivalent component, and the seal housing 250receives a piston 260 which is pinned by shear pins 265 to the seal body250, and is sealed thereto by an O-ring. The piston 260 has a flange 262which limits the axial travel of the piston 260 within the seal housing250, and is biased by the spring 270 which is held in compressionbetween the inner surface of the piston 260 and a shoulder within thespring cavity 257, urging the piston upwards.

In this example, when a cement job is to be run, the string is assembledduring insertion typically including casing shoe and float valves at thelower end of the string, followed by a shoe landing sub 240. The shoelanding sub 240 has a tapered seat 241 above a cylindrical section 242adapted to receive the nose 280 of the plug 201. Once the string hasbeen run into the hole cement is pumped through the string, and ischased by the plug 201 to wipe the casing and liner of cement. The body210 has external vanes along the outside of the central section, whichdeform against the inner surface of the liner or casing, and are adaptedto wipe the inner surface of the liner following the injection of thecement from the surface.

When the plug 201 reaches the shoe landing sub 240 the nose 280 of theplug 201 lands in cylindrical section 242 below the tapered seat 241 andseals the bore 240 b of the shoe landing sub 240 as previously describedfor earlier examples. The sealed position is shown in FIG. 8, in whichthe seals on the nose 280 are compressed between the nose 280 and thecylindrical section, but the plug 201 has not yet fully engaged thetapered seat 241, because the lower end of the nose 280 has landed onthe upper end of a port sleeve 300 which is pinned to the landing sub240. The port sleeve 300 is sealed within the bore 240 b of the landingsub 240, and seals off radial ports 245 connecting the bore 240 b withthe external surface of the landing sub 240. When pinned in position asshown in FIG. 8, the port sleeve 300 denies fluid passage through theradial ports 245. The pins 246 holding the port sleeve 300 are typicallyrated at a similar strength to the pins 265 holding the piston 260 inthe seal housing 250, but they could be different.

Optionally the plug can be latched or locked to the body by a latchdevice. In this case a latch secures the plug in one direction i.e. fromdrifting back in the reverse (upward) direction, stopping the seals fromcoming back out of the landing sub 240 but optionally not restrictingthe space in the forward direction that is later required to shift theport sleeve 300.

In one modification applicable to this example, the nose of the body ofthe plug can optionally incorporate one or more radial ports orflowpaths to permit fluid communication across the interface between theplug and the sleeve 300 in the event that the sleeve 300 remains inabutment with the plug after uncovering the radial ports 245. The sleeve300 is typically moved from its initial position by the axial urging ofthe nose 280 of the plug 201 when the pins 246 and 265 shear. Sometimes,momentum from the shear might act on the plug 300 such that it continuesmoving down the bore 240 b after the plug 201 is arrested in thepositions shown in FIGS. 8-10, for example, the sleeve 300 mightcontinue to move under momentum to the position shown in FIG. 10,thereby coming to rest in a position that is spaced axially away fromthe nose of the plug 201, below the axial position of the ports 245.However, in some cases, the sleeve 300 might remain in contact with thenose 280 of the plug 201 during the shear. The optional feature of theradial flowpaths in the nose shown in FIG. 12 permit fluid communicationbetween the bore of the plug 201′ and the radial ports 245′ even in theevent that the sleeve 300′ remains in abutment with the nose. The portsin the nose in this modification are optionally provided by extensionsof the nose with flowpaths between nose prongs 281 shown in FIG. 12.FIG. 12 also shows a further optional modification according to thisexample, in which the nose is tapered to be partially received in thebore of the sleeve 300′. Optionally the ports are disposed below theseals in the nose 280. Optionally the ports are disposed above the sealson the sleeve 300, i.e. between the two sets of seals. Optionally, whenthe plug is fully seated and has been arrested in the seat, the nose(e.g. the nose prongs) pushes the port sleeve axially downwards in thebore of the landing sub until the seals on the port sleeve clear theradial port in the tubular (e.g. the landing sub). The ports canfacilitate fluid transfer between the bore of the plug and the radialports in the landing sub (in either direction).

The well is conveniently shut in from both directions during this phaseand can optionally be left for any period of time—during which time thecement is able to dry.

In the FIG. 8 position, although the body 210 is held up by the pinnedport sleeve 300 and the bore 240 b of the landing sub 240 is closed bythe seals of the nose 280 of the plug 201 which are compressed withinthe cylindrical section, the tapered section 281 on the body 210 has notyet fully engaged with the tapered seat 241 on the landing sub 241,although in some examples, the remaining distance to travel before fullengagement is achieved is optionally very small, e.g. a matter ofmillimetres, so in some examples, movement of the body 210 between theFIGS. 9 and 10 positions does not substantially change the volume of thestring before the plug 201. Optionally only the pins 246 are holding thebody 210 in the FIG. 8 position. So higher pressure applied above theseated plug 201 eventually shears both the pins 265 and 246, causing theplug 201 to move down the bore of the landing sub 240 from the positionin FIG. 8 to the position in FIG. 9, until tapered section 281 on thebody 210 is fully seated on the tapered seat 241 on the landing sub 240,and the port sleeve 300 has moved down the bore of the landing sub 240.The distance moved by the sleeve 300 is un-important (as communicationis not yet established through the plug above. The travel of the sleeve300 can optionally be short enough to only shear the pins or long enoughto fully or partially expose the ports below and is initially controlledby the length of the protruding nose of the plug below the seal(s) andthe available space between the (optionally tapered) faces of the plugand landing sub 240. At this stage, although the ports may be exposed,they do not yet transmit fluid because the plug above has not yet openedand so there is no meaningful communication.

Typically the pressure sufficient to shear the pins 265, 246 is lessthan full pressure test values which could be around 10 kpsi (approx.68.9 MPa). It does not particularly matter which of the pins 265, 246shear first. Optionally the pressure required to shear the pins 265, 246is similar, and is also optionally sufficient to maintain compression ofthe spring 270 by the piston 260, thereby keeping the bore 210 b closed.This position as shown in FIG. 8 can be held with the plug forming atemporary barrier, closing the bore 240 b since the nose 280 is sealedin the cylindrical section, and keeping the bore 240 b sealed off fromthe radial ports 245, since the port sleeve 300 has not moved down farenough to uncover them. The position can be held by the latching devicewithout necessarily requiring pressure to be applied from the surface,although this remains an option. This position can therefore be held foran indefinite period until the cement dries. The well is convenientlyshut in from both directions during this phase.

The FIG. 9 position shows the configuration of the plug during apressure test, with a higher pressure of around 10 kpsi (approx. 68.9MPa) being applied from the surface, sufficient to shear the pins 265and 246. While the plug 201 is fully seated and cannot move any furtherdown the bore 240 b, the port sleeve 300 is typically not exposed to anydirect pressure and is typically only moved down the bore 240 b becauseit is being urged by the lower end of the plug 201 landed on the upperend of the port sleeve 300, so when the plug 201 reaches its finalposition shown in FIG. 9, the port sleeve 300 typically stops moving,optionally in a position in which the ports 245 are still sealed offfrom the bore 240 b. Thus optionally in the full pressure test positionshown in FIG. 9, the well is still closed in from both directions.

The force applied by the pressure test shears the pins 265 holding thepiston 260 within the seal housing 250, and the piston 260 therefore isfree to move downwards in the body 210 under the pressure differential,to compress the coiled spring 270 within the spring cavity 257 until theflange 262 on the piston tops out on the seal housing 250, essentiallyas previously described for the first example. Once the pressure test isconcluded, the pressure above the sealed piston 260 is bled off aspreviously described until the downward force applied by the pressuredifferential acting on the sealed piston 260 is less than the upwardforce applied by the coiled spring 270 held in compression below thepiston 260, at which point the coiled spring 270 expands and pushes thepiston 260 out of the seal housing 250. At this point communicationthrough the bore 210 b is re-established again, essentially aspreviously described.

When the piston 260 is ejected from the body 210, the higher flow ratesthrough the bore 210 b of the plug 201 urges the port sleeve 300 downthe bore to fully uncover the radial ports 245, permitting communicationbetween the bore of the string and the radial ports to permit productionof hydrocarbons, or if required, fracturing etc.

While not every aspect of the first and second examples has beendescribed with respect to the second example, any or all of the featuresof the first and second examples could be incorporated within the thirdexample, and vice versa.

In use, the string is assembled from the surface and run into the holecommencing with the shoe and optionally the float valves run immediatelybelow the landing sub 240, followed by the remainder of the liner andcasing above it. The volume of the string below the pinned sleeve 300can be accurately measured, and can be kept relatively small. Theposition of the radial ports 245 can be accurately established, and thecross-sectional area of the ports 245 can likewise be accuratelyestablished (e.g. at the surface) for the appropriate job, be it frac,well stimulating or hydrocarbon production or influx. The string is runinto the hole with the port sleeve 300 in place to close the radialports 245 as previously described, and with the landing sub 240 near tothe bottom of the string. Optionally, the ports 245 can be circular incross-section, but this can be varied, and in different examples, theports 245 can optionally comprise slots which can optionally extendcircumferentially around the landing sub for at least a short distance.In some examples, the slots 245 can be arranged in axially spaced rowswhich are offset and which overlap, permitting at some point influx ofoil or gas and/or also if required injection of fluid through the portsaround the full diameter of the landing sub 240, as shown, for example,in FIG. 11.

In operation, following the injection of the cement in a quantitycarefully chosen to fill the annulus between the outside of the stringand the inside of the bore of the well, the cement is chased with aspacer fluid such as water, followed by the plug 201. The volume ofspacer fluid injected between the plug and the cement is optionallycarefully calculated to be the same as or very close to the volume ofthe string beneath the landing shoe cylindrical portion 242 before theend of the bore of the well, so that the spacer fluid displacessubstantially all of the cement ahead of it into the annulus. The plugis pumped down the well, chasing the spacer fluid and cement below it,and wiping the inner surface of the liner or surface casing as ittravels, pushing the cement out of the bottom of the string and up intothe annulus between the string and the bore. The operator can beconfident that during the injection of the cement and until the plug 201is seated freely and/or latched in the landing sub 240, the radial ports245 will remain closed at the bump test pressure, and all of the cementwill be injected through the float shoe. Also due to the potentialaccess above the shoe, through the ported sleeve, the calculated amountof spacer fluid required between the cement and plug is less criticalthan it normally would be, thus being more desirable to the operator.

As the plug lands at the landing sub 240, and seals in the cylindricalsection 242, the operator can be confident that the fluid between thelanded plug and the bottom of the string is occupied by spacer fluidrather than by cement, since this has been accurately measured at thesurface, and is (and is optionally a manageably small volume e.g. a few10s of Litres). Advantageously also, the cementing has been deliberatelycompleted as a “wet shoe” job, leaving minimal set cement within thestring, and substantially all of the set cement being displaced into theannulus outside the string by the spacer fluid. Once the plug 201 haslanded on the pinned port sleeve 300, a bump test can be performed toconfirm that the tool has been landed, typically at a relatively lowpressure of approximately 1000 psi (for example 6.89 MPa) which isinsufficient to shear any of the pins within the assembly, but which issufficient to confirm the position of the plug 201 at the landing sub240, which thereby confirms that the cement has been pushed out of thestring and is now mainly occupying the annulus.

In a first example, in a situation where the cement has dried fullyoutside the annulus and the string below the landing sub 240 is filledwith spacer fluid only, the operator can then perform a full systempressure test at high pressure to shear both of the pins 246 and 265 sothat the plug moves into the FIG. 9 configuration. The test pressure canbe held for as long as required and after pressure is bled off, theforce of the spring 270, which has been maintained in compression in theFIG. 9 configuration, expands to push the piston 260 out of the upperend of the body 210 of the plug 201, thereby re-establishing fluidcommunication through the bore of the plug, and permitting flowtherethrough. The flow rate of fluid through the now open plug (oralternatively a pressure differential across the sleeve 300) typicallymoves the sleeve 300 down the bore 240 b to fully expose the radialports 245 (this may not be required as the ports may already be fullyexposed at the point of shearing the sleeve down), which permitshydraulic fracturing operations, if required without furtherintervention.

The first frac or production zone can optionally be established entirelybelow the wiper plug and the cement, which is of significant advantage,because the thin annular layer of cement immediately outside the ports245 is easily fractured by the hydraulic pressures applied through thestring during fracturing operations. This means that the first frac zonecan be very much closer to the intended reservoir than was previouslypermitted.

In some situations, the miscalculation of the volume of spacer fluidwithin the string leads to set cement in the string either in or belowthe float shoe underneath the landing sub 240. In such situations, apressure test can be conducted as previously described and held for aslong as needed, and the first frac zone can then be initiated throughthe ports. Therefore, in some examples, even where mistakes in thecement job lead to cement plugs occurring below the string, examples ofthe present invention still permit hydraulic fracturing operationswithout mechanical intervention at the plug, simply by operating thesurface pumps to induce pressure changes.

In one example, the body 10 may optionally incorporate a channelpermitting selective fluid communication across the sealing member,bypassing the sealing member when seated (and sealed) in the body. Thechannel optionally incorporates a seal such as a burst disc or someother selectively actuable sealing device that prevents fluidcommunication through the channel below a burst pressure, but which isadapted to be disrupted by a pressure differential above the burstpressure to permit fluid communication through the channel. The burstdisc can optionally be added as a safety precaution set to burst if thetubular above the seated plug is over-pressurised. This optionalmodification is potentially useful if the pressure below the seated plugis unexpectedly low, such that when the sealing member has transitionedto the second position, unlocking the sealing member from the body, thepressure differential acting on the seated sealing member can beequalised by rupturing the burst disc, thereby reducing the force neededby the spring to push the sealing member from the second configurationto the third. Optionally the burst disc is rated to a pressure thresholdabove the intended pressure test threshold, so that the burst discremains intact at normal operating pressure, and is only ruptured if thepressure below the seated plug is too low to push the sealing memberfrom the second configuration to the third by the force of the springalone. Optionally the rating of the burst disc can be significantlyhigher than the planned test pressure. Optionally the burst disc can bedisposed in the sealing member, or optionally in another part of thebody 10, such as the seal housing, for example, below the seated sealingmember.

When intact, the burst disc can optionally occlude a small passageway orrestriction of known (small) cross-sectional area extending through thesealing device (or optionally through the wall of the plug body) so thatin the event of premature rupture of the burst disc, any drop inpressure above the plug (which can be monitored at the surface) isfirstly less dramatic and secondly can be monitored over a period oftime. In some cases, selecting the restriction to be suitably small canallow the pressure differential across the ruptured burst disc to bereplenished to original pressure using surface pumps (because therestriction has a known small cross-sectional area providing aquantifiable maximum pressure drop). This helps the surface operator tointerpret measured pressure changes above the plug resulting from theruptured burst disc, which can more easily be attributed to the rupturedburst disc itself rather than to other losses in wellbore integrity.Suitable calculations can be based on the density of the fluid, numberof passageways, flow area restriction on passageways and flow rate ofthe surface pumps to quantify the pressure drop across the ruptureddisc.

Examples of the present invention permit several distinct advantages,namely reducing the required length of the shoe track, increasing theproduction zone, avoiding reliance on fluid timers or dissolving parts,reducing reliance on coiled tubing operations and perforatingoperations, more consistent and controllable fracturing ports which canbe more accurately positioned than previously possible, and can lead toless weakening of the structural integrity of the material surroundingthe ports. In addition, the claimed combination of features also permitsfor more accurate estimation of the required amount of space fluid touse for a given cement job, therefore leading to more consistentlysatisfactory cement jobs and fewer errors with that phase of the well.

1. A wellbore plug comprising: a body having an axis and a bore adaptedto transmit fluid between a first end of the body and a second end ofthe body, the body being adapted to be received within a tubular in anoil or gas well, and being adapted to engage a seat within the oil orgas well tubular to seal an annulus between the outer surface of thebody and an inner surface of the tubular; a sealing member adapted toocclude the bore through the body to resist fluid flow through the boreof the body when the wellbore plug is in a first configuration; aresilient device adapted to urge the sealing member towards one end ofthe body when the wellbore plug is in the first configuration; a lockingmember adapted to lock the sealing member in the first configuration,and adapted to be unlocked in response to pressure within the bore abovea pressure threshold; wherein unlocking of the locking member permitsmovement of the sealing member within the bore to shift the wellboreplug from the first configuration to a second configuration; whereinmovement of the sealing member in response to expansion of the resilientdevice when pressure within the bore is reduced below the thresholdshifts the wellbore plug from the second configuration to a thirdconfiguration; and wherein in the third configuration, the sealingmember permits fluid passage through the bore between the first andsecond ends of the body.
 2. (canceled)
 3. A wellbore plug as claimed inclaim 1, wherein the sealing member is restrained against axial movementwithin the bore by the locking member.
 4. A wellbore plug as claimed inclaim 1, wherein the sealing member moves in one direction when thewellbore plug shifts from the first to the second configuration, and inthe opposite direction when the wellbore plug shifts from the secondconfiguration to the third configuration.
 5. (canceled)
 6. A wellboreplug as claimed in claim 1, wherein the bore has a catching chamberhaving an inner diameter that is larger than the outer diameter of thesealing member, and wherein the catching chamber provides a clearancepermitting fluid flow between the inner surface of the bore of the bodyand the outer surface of the sealing member when the sealing member isin the third configuration.
 7. A wellbore plug as claimed in claim 6,wherein the second end of the body incorporates a seal adapted to engagethe seat within the oil or gas well tubular to seal the annulus betweenthe outer surface of the body and the inner surface of the tubular, andwherein the catching chamber is disposed between the first end of thebody and the sealing member when the sealing member is in the firstconfiguration.
 8. (canceled)
 9. A wellbore plug as claimed in claim 6,wherein the catching chamber retains the sealing member in the thirdconfiguration and permits fluid flow around the sealing member withinthe catching chamber.
 10. A wellbore plug as claimed in claim 1, whereinthe bore comprises a seal housing having an inner diameter in which thesealing device is received in a sliding fit, and wherein a resilientseal is compressed between the outer surface of the sealing device andthe inner surface of the seal housing.
 11. A wellbore plug as claimed inclaim 10, wherein the seal housing incorporates a first shoulder facingthe first end of the body, and adapted to limit axial movement of thesealing member in a direction from the first end of the body to thesecond end within the seal housing by abutting a shoulder facing thesecond end of the body on the sealing member.
 12. A wellbore plug asclaimed in claim 10, wherein the seal housing is radially stepped, witha larger diameter portion closer to the first end than to the secondend, and a smaller diameter portion closer to the second end than to thefirst end.
 13. A wellbore plug as claimed in claim 1, wherein thesealing member prevents fluid flow within the bore in the first andsecond configurations.
 14. A wellbore plug as claimed in claim 1,wherein the resilient device is maintained in compression between thesealing member and a shoulder in the body in the first and secondconfigurations, and wherein the shoulder is disposed between the secondend of the body and the sealing member.
 15. A wellbore plug as claimedin claim 1, wherein the movement of the sealing member as the wellboreplug shifts from the first to the second configuration from compressesthe resilient device.
 16. A wellbore plug as claimed in claim 1, whereinthe resilient device is held in compression in the first and secondconfigurations, and expands when the wellbore plug shifts from thesecond configuration to the third configuration.
 17. A wellbore plug asclaimed in claim 1, wherein the sealing member and the body areseparate.
 18. A wellbore plug as claimed in claim 1, wherein the bodycontains at least one port permitting fluid communication between thebore of the body and an outer surface of the body between the sealingmember and the second end of the body, and wherein the port is adaptedto be closed by a sleeve that slides axially within the bore. 19.(canceled)
 20. A wellbore plug as claimed in claim 1, wherein thesealing member is separate from the body, and wherein the body isadapted to be latched into the tubular, between a first section of thetubular and a second section of the tubular and installed with thetubular during deployment of the tubular, and wherein the bodyincorporates a seat adapted to seat the sealing member when the sealingmember lands on the latched body, and wherein the body is adapted to beunlatched from the tubular by a pressure differential applied across theseated sealing member on the latched body to permit the body to travelaxially along the second section of the tubular.
 21. A wellbore plug asclaimed in claim 1, wherein the sealing member incorporates a channelpermitting selective fluid communication across the sealing member whenseated in the body, and wherein the channel incorporates a sealpreventing fluid communication through the channel below a pressuredifferential above a burst pressure, and wherein the seal is adapted tobe disrupted by a pressure differential above the burst pressure topermit fluid communication through the channel. 22-33. (canceled)
 34. Awellbore plug comprising: a body having an axis and a bore adapted totransmit fluid between a first end of the body and a second end of thebody, the body being adapted to be received within a tubular in an oilor gas well, and being adapted to engage a seat within the oil or gaswell tubular to seal an annulus between the outer surface of the bodyand an inner surface of the tubular; a sealing member adapted to occludethe bore through the body to resist fluid flow through the bore of thebody when the wellbore plug is in a first configuration; a resilientdevice adapted to urge the sealing member towards one end of the bodywhen the wellbore plug is in the first configuration; a locking memberadapted to lock the sealing member against axial movement in the bore inthe first configuration, and adapted to be unlocked in response topressure within the bore above a pressure threshold; wherein unlockingof the locking member permits movement of the sealing member within thebore to shift the wellbore plug from the first configuration to a secondconfiguration; wherein movement of the sealing member in response toexpansion of the resilient device when pressure within the bore isreduced below the threshold shifts the wellbore plug from the secondconfiguration to a third configuration; and wherein in the thirdconfiguration, the sealing member permits fluid passage through the borebetween the first and second ends of the body; wherein the sealingmember moves in one direction when the wellbore plug shifts from thefirst to the second configuration, and in the opposite direction whenthe wellbore plug shifts from the second configuration to the thirdconfiguration; wherein the bore has a catching chamber having an innerdiameter that is larger than the outer diameter of the sealing member,and wherein the catching chamber provides a clearance permitting fluidflow between the inner surface of the bore of the body and the outersurface of the sealing member when the sealing member is in the thirdconfiguration.
 35. A wellbore plug comprising: a body having an axis anda bore adapted to transmit fluid between a first end of the body and asecond end of the body, the body being adapted to be received within atubular in an oil or gas well, and being adapted to engage a seat withinthe oil or gas well tubular to seal an annulus between the outer surfaceof the body and an inner surface of the tubular; a sealing memberadapted to occlude the bore through the body to resist fluid flowthrough the bore of the body when the wellbore plug is in a firstconfiguration; a resilient device adapted to urge the sealing membertowards one end of the body when the wellbore plug is in the firstconfiguration; a locking member adapted to lock the sealing memberagainst axial movement in the bore in the first configuration, andadapted to be unlocked in response to pressure within the bore above apressure threshold; wherein unlocking of the locking member permitsmovement of the sealing member within the bore to shift the wellboreplug from the first configuration to a second configuration; whereinmovement of the sealing member in response to expansion of the resilientdevice when pressure within the bore is reduced below the thresholdshifts the wellbore plug from the second configuration to a thirdconfiguration; wherein in the third configuration, the sealing memberpermits fluid passage through the bore between the first and second endsof the body; wherein the resilient device is maintained in compressionbetween the sealing member and a shoulder in the body in the first andsecond configurations, and wherein the shoulder is disposed between thesecond end of the body and the sealing member; and wherein the resilientdevice is held in compression in the first and second configurations,and expands when the wellbore plug shifts from the second configurationto the third configuration.
 36. A wellbore plug as claimed in claim 35,wherein the bore has a catching chamber having an inner diameter that islarger than the outer diameter of the sealing member, and wherein thecatching chamber provides a clearance permitting fluid flow between theinner surface of the bore of the body and the outer surface of thesealing member when the sealing member is in the third configuration,wherein the second end of the body incorporates a seal adapted to engagethe seat within the oil or gas well tubular to seal the annulus betweenthe outer surface of the body and the inner surface of the tubular, andwherein the catching chamber is disposed between the first end of thebody and the sealing member when the sealing member is in the firstconfiguration.